Without limiting the scope of the invention, its background is described in connection with novel apparatus and methods for service of subsea pipelines.
It is currently estimated that approximately 60% of the world's petroleum production derives from offshore operations. To meet demands, and in an environment of increased values for oil and gas, exploration and subsequent production is being undertaken in deeper and deeper waters. For example, oil and gas is now being produced off the Louisiana coast in 9,000 feet of water. These offshore efforts have required expensive specialized solutions including establishment of extensive networks of subsea pipelines for transport of oil and gas from well heads to gathering structures, hub facilities and to onshore processing refineries.
The cost of laying pipelines subsea is immense and, therefore, the pipelines are carefully managed and serviced to extend their workable lives. Pipelines running from large fields are engineered to have a design life of thirty to fifty years. Occasionally pipelines or “flow lines” are damaged during laying of the pipe, or as a consequence of subsequent physical damage or environmental conditions. Excessive bending of pipe results in structural damage including buckling. Where damage results in a crack in the pipe and fluid inflow this is termed a “wet buckle.” Whether occurring during laying or thereafter, sections of buckled pipeline must be removed from the pipeline and repaired.
In one method of recovering wet buckled pipe disclosed in U.S. Pat. No. 5,044,827 (Gray et al.), a submersible vessel (“SV”) is used to inflate lift bags beneath the submerged pipeline followed by cutting out the damaged section of pipe. Finally, the SV inserts a recovery head into an end of the cut pipe to grip the pipe for winching to the surface. In order to lift the damaged sections to the surface, wet buckled pipe must be evacuated of fluid or “dewatered” to reduce its weight. As described by Gray, pipeline sections typically are dewatered using topside pumps to provide compressed gas to drive a dewatering pig from the surface through the pipeline, stopping at the subsea recovery head. Alternatively, as described in U.S. Pat. No. 3,777,499 (Matthews), one subsea end of the pipeline can be sealed with a cap that includes a gas inlet and gas supplied from the surface can be introduced from one end while liquids are pumped from the other end using a pump lowered and powered from the surface and disposed at the other end of the pipeline.
Compressed gas for driving a dewatering pig must be provided at sufficient pressure to drive the pig considering several dynamic components including: the hydrostatic pressure of the water over the pipe, the friction pressure of the fluid as it moves through the pipe, and the friction of the pig against the pipeline walls (pig differential). Because hydrostatic pressure is by far the most significant dynamic component as water depth increases, topside dewatering has required very large top-side air compression spreads that must remain in position over the damaged pipelines during recovery efforts. What are needed are subsea apparatus and methods able to provide recovery of damaged pipeline that avoid the need for large topside gas compressor spreads and/or topside powered dewatering pumps.
Another required pipeline service relates to chemical sampling and treatment. Sections of pipeline that are waiting to be put into service, or that have been damaged and are awaiting remediation, are typically chemically treated to prevent corrosion. In addition, in-service pipelines may become clogged with contaminants that reduce flow, particularly where the pipelines carry a number of different products in multiphase flow. These include hydrates, asphaltenes, scale, and paraffins. For each of these contaminants and build-ups, specific remediative chemical treatments have been developed and are often combined with pigging to physically clean the pipeline and to load the pipeline with the remediative chemicals. Pigging is typically implemented via surface power wherein power fluid or gas is conveyed to a subsea pipeline manifold via coiled tubing run from the surface. Likewise, chemical injection pumps are typically located topside. Testing for the efficacy of the remediative chemical treatment has traditionally been done by modeling of supposed subsea conditions, including factors of temperature, pressure and the type of product carried in the pipeline. Actual subsea sampling of pipeline sections has not heretofore been possible.
In some cases, service is required on a portion of a subsea product or flow line system that has been in service and contains hydrocarbon products. Removal of the product to the surface without environmental release of the hydrocarbon product has heretofore required connection to the surface via coiled tubing or drill string or has required complete decommissioning and recommissioning. Subsea removal of product has not been heretofore possible and represents an unmet need in the industry.
Another heretofore underserved pipeline service relates to leak detection, where the presence of a wet buckle must be detected, or more generally where the continued ability of a pipeline both to contain its contents, and to protect the contents from in-flow may need to be assessed. In the past, testing for leaks has generally required putting in place a means to monitor changes in pressure, or alternatively the facility to detect noise made by leakage.
What are needed are subsea pipeline service apparatus and methods able to detect leaks in pipelines, to dewater pipelines such that damaged pipelines can be lifted for repair, as well as apparatus and methods able to provide sampling of the in situ chemical mileu of chemically treated pipelines, remove product from flowline system elements, and, if desired, to treat sections of pipeline, all using a completely subsea service skid.